Holly Energy Partners, L.P. Reports Third Quarter Results

DALLAS–(BUSINESS WIRE)–Holly Energy Partners, L.P. (“HEP” or the “Partnership”) (NYSE:HEP) today reported financial results for the third quarter of 2015. For the quarter, distributable cash flow was $50.3 million, up $4.7 million, or 10% compared to the third quarter of 2014. HEP announced its 44th consecutive distribution increase on October 22, 2015, raising the quarterly distribution from $0.545 to $0.555 per unit, which represents an increase of 6.2% over the distribution for the third quarter of 2014.

Net income attributable to Holly Energy Partners for the third quarter was $34.5 million ($0.40 per basic and diluted limited partner unit) compared to $29.7 million ($0.35 per basic and diluted limited partner unit) for the third quarter of 2014. The increase in earnings is primarily due to higher pipeline and terminal volumes and annual tariff increases.

Commenting on the third quarter of 2015, Mike Jennings, Chief Executive Officer, stated, “We are pleased our financial results for the third quarter of 2015 allowed us to maintain our record of raising quarterly distributions. Recent performance and future prospects enabled us to raise our distribution by a full $0.01 per unit this quarter. HEP’s steady growth is supported by our fee-based commercial structure with underlying long-term minimum commitments by our key customers.

“We continue to leverage our logistic capabilities and HollyFrontier Corporation’s refining footprint to create unique third party acquisition opportunities like our acquisition of a 50% interest in the Frontier Pipeline during the third quarter of 2015. In addition, we completed our acquisition of dropdown assets including the naphtha fractionation and hydrogen generation units at HollyFrontier’s El Dorado refinery as of November 1, 2015. This acquisition, which is supported by a long-term contract with HollyFrontier, is 100% fee-based with no commodity risk or exposure, like all of HEP’s past acquisitions from HollyFrontier.

Revenues for the quarter were $88.4 million, an increase of $6.3 million compared to the third quarter of 2014 due to the effect of higher pipeline volumes and annual tariff increases. Overall pipeline volumes were up 22% compared to the three months ended September 30, 2014, largely due to increased volumes from the New Mexico gathering system expansion.

Revenues from our refined product pipelines were $31.0 million, an increase of $2.3 million compared to the third quarter of 2014 mainly due to increased revenue from UNEV pipeline of $1.9 million in addition to increased volumes and annual tariff increases. Shipments averaged 197.8 mbpd compared to 188.0 mbpd for the third quarter of 2014.

Revenues from our intermediate pipelines were $7.5 million, an increase of $0.5 million, on shipments averaging 148.8 mbpd compared to 139.5 mbpd for the third quarter of 2014. Revenues increased mainly due to an increase in volumes and annual tariff increases.

Revenues from our crude pipelines were $17.4 million, an increase of $2.8 million, on shipments averaging 297.8 mbpd compared to 199.6 mbpd for the third quarter of 2014. Revenues increased mainly due to a $1.6 million increase in revenue from the New Mexico gathering system expansion. The increase in volumes is due to increased crude production in the Artesia Basin as well as the reversal of the Roadrunner pipeline, which made it possible for HFC to purchase and HEP to transport crude volumes in excess of HFC refining capacity.

Revenues from terminal, tankage and loading rack fees were $32.5 million, an increase of $0.7 million compared to the third quarter of 2014. Refined products terminalled in our facilities averaged 370.9 mbpd compared to 325.9 mbpd for the third quarter of 2014. Revenues increased due to our first quarter 2015 acquisition of an existing crude tank farm adjacent to HFC’s El Dorado refinery as well as increased volumes and annual tariff increases.

Revenues for the three months ended September 30, 2015, include the recognition of $0.6 million of prior shortfalls billed to shippers in 2014 as they did not meet their minimum volume commitments within the contractual make-up period. As of September 30, 2015, shortfall deferred revenue in our consolidated balance sheet was $7.8 million. Such deferred revenue will be recognized in earnings either as (a) payment for shipments in excess of guaranteed levels, if and to the extent the pipeline system has the necessary capacity for shipments in excess of guaranteed levels, or (b) when shipping rights expire unused over the contractual make-up period.

Nine Months Ended September 30, 2015 Revenue Highlights

Revenues for the nine months ended September 30, 2015, were $261.6 million, an increase of $17.5 million compared to the nine months ended September 30, 2014. This is due principally to the effect of annual tariff increases and increased pipeline shipments largely due to increased volumes from the New Mexico gathering system expansion.

Revenues from our refined product pipelines were $96.8 million, an increase of $7.2 million primarily due to increased volumes and annual tariff increases. Shipments averaged 193.5 mbpd compared to 180.2 mbpd for the nine months ended September 30, 2014, largely due to lower volumes in the second quarter of 2014 resulting from major maintenance performed at Alon’s Big Spring refinery as well as higher spot volumes on our UNEV pipeline.

Revenues from our intermediate pipelines were $21.5 million, a decrease of $0.1 million, on shipments averaging 143.4 mbpd compared to 140.5 mbpd for the nine months ended September 30, 2014. The decrease in revenue was due to the effects of a $0.7 million decrease in deferred revenue realized offset by higher volumes and annual tariff increases.

Revenues from our crude pipelines were $49.5 million, an increase of $9.3 million, on shipments averaging 292.2 mbpd compared to 185.1 mbpd for the nine months ended September 30, 2014. Revenues increased due to the annual tariff increases and increased volume in addition to $5.8 million in increased revenue from the New Mexico gathering system expansion.

Revenues from terminal, tankage and loading rack fees were $93.9 million, an increase of $1.1 million compared to the nine months ended September 30, 2014. This increase is due to annual fee increases and increased terminal volumes. Refined products terminalled in our facilities averaged 359.3 mbpd compared to 330.6 mbpd for the nine months ended September 30, 2014, largely due to lower volumes in the second quarter of 2014 resulting from major maintenance performed at Alon’s Big Spring refinery.

Revenues for the nine months ended September 30, 2015, include the recognition of $8.6 million of prior shortfalls billed to shippers in 2014, as they did not meet their minimum volume commitments within the contractual make-up period.

Operating Costs and Expenses Highlights

Operating costs and expenses were $44.1 million and $133.1 million for the three and the nine months ended September 30, 2015, respectively, representing an increase of $0.9 million from the three months ended September 30, 2014, and an increase of $5.4 million from the nine months ended September 30, 2014. The increase for the nine months ended September 30, 2015, is primarily due to higher maintenance project expenses of $6.8 million and an increase in environmental remediation provisions, net of recovery from third parties, of $1.7 million offset by lower employee costs of $3.5 million as a result of the secondment of employees in El Dorado and Cheyenne.

Interest expense was $9.5 million and $27.3 million for the three and the nine months ended September 30, 2015, respectively, representing an increase of $0.9 million and a decrease of $0.1 million over the same periods of 2014. The increase for the three months ended September 30, 2015, is due to an increase in borrowings under our credit agreement. The decrease for the nine months ended September 30, 2015, is principally due to the early extinguishment of our 8.25% Senior Notes in March 2014.

We have scheduled a webcast conference call today at 4:00 PM Eastern Time to discuss financial results. This webcast may be accessed at: https://event.webcasts.com/starthere.jsp?ei=1079834.

An audio archive of this webcast will be available using the above noted link through November 18, 2015.

HollyFrontier Corporation, headquartered in Dallas, Texas, is an independent petroleum refiner and marketer that produces high value light products such as gasoline, diesel fuel, jet fuel and other specialty products. HollyFrontier operates through its subsidiaries a 135,000 barrels-per-stream-day (“bpsd”) refinery located in El Dorado, Kansas, a 125,000 bpsd refinery in Tulsa, Oklahoma, a 100,000 bpsd refinery located in Artesia, New Mexico, a 52,000 bpsd refinery located in Cheyenne, Wyoming, and a 31,000 bpsd refinery in Woods Cross, Utah. HollyFrontier markets its refined products principally in the Southwest U.S., the Rocky Mountains extending into the Pacific Northwest and in other neighboring Plains states. A subsidiary of HollyFrontier also owns a 39% interest (including the general partner interest) in Holly Energy Partners, L.P.

The statements in this press release relating to matters that are not historical facts are “forward-looking statements” within the meaning of the federal securities laws. Forward-looking statements use words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “should,” “would,” “could,” “believe,” “may,” and similar expressions and statements regarding our plans and objectives for future operations. These statements are based on our beliefs and assumptions and those of our general partner using currently available information and expectations as of the date hereof, are not guarantees of future performance and involve certain risks and uncertainties. Although we and our general partner believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give assurance that our expectations will prove to be correct. All statements concerning our expectations for future results of operations are based on forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Certain factors could cause actual results to differ materially from results anticipated in the forward-looking-statements. These factors include, but are not limited to:

risks and uncertainties with respect to the actual quantities of petroleum products and crude oil shipped on our pipelines and/or terminalled, stored and throughput in our terminals;

the economic viability of HollyFrontier Corporation, Alon USA, Inc. and our other customers;

the demand for refined petroleum products in markets we serve;

our ability to purchase and integrate future acquired operations;

our ability to complete previously announced or contemplated acquisitions;

the availability and cost of additional debt and equity financing;

the possibility of reductions in production or shutdowns at refineries utilizing our pipeline and terminal facilities;

the effects of current and future government regulations and policies;

the possibility of terrorist attacks and the consequences of any such attacks;

general economic conditions; and

other financial, operations and legal risks and uncertainties detailed from time to time in our Securities and Exchange Commission filings.

The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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RESULTS OF OPERATIONS (Unaudited)

Income, Distributable Cash Flow and Volumes

The following tables present income, distributable cash flow and volume information for the three and the nine months ended September 30, 2015 and 2014.

Three Months EndedSeptember 30,

Change from

2015

2014

2014

(In thousands, except per unit data)

Revenues

Pipelines:

Affiliates – refined product pipelines

$

19,945

$

17,811

$

2,134

Affiliates – intermediate pipelines

7,488

7,038

450

Affiliates – crude pipelines

17,393

14,557

2,836

44,826

39,406

5,420

Third parties – refined product pipelines

11,095

10,939

156

55,921

50,345

5,576

Terminals, tanks and loading racks:

Affiliates

28,890

28,044

846

Third parties

3,578

3,741

(163

)

32,468

31,785

683

Total revenues

88,389

82,130

6,259

Operating costs and expenses:

Operations

24,095

25,456

(1,361

)

Depreciation and amortization

16,326

15,483

843

General and administrative

3,673

2,266

1,407

44,094

43,205

889

Operating income

44,295

38,925

5,370

Equity in earnings of equity method investments

1,269

880

389

Interest expense, including amortization

(9,486

)

(8,585

)

(901

)

Interest income

381

—

381

Other income

176

11

165

(7,660

)

(7,694

)

34

Income before income taxes

36,635

31,231

5,404

State income tax expense

(69

)

(42

)

(27

)

Net income

36,566

31,189

5,377

Allocation of net income attributable to noncontrolling interests

(2,081

)

(1,509

)

(572

)

Net income attributable to Holly Energy Partners

34,485

29,680

4,805

General partner interest in net income, including incentive distributions(1)

(10,830

)

(8,940

)

(1,890

)

Limited partners’ interest in net income

$

23,655

$

20,740

$

2,915

Limited partners’ earnings per unit – basic and diluted:(1)

$

0.40

$

0.35

$

0.05

Weighted average limited partners’ units outstanding

58,657

58,657

—

EBITDA(2)

$

59,985

$

53,790

$

6,195

Distributable cash flow(3)

$

50,306

$

45,581

$

4,725

Volumes (bpd)

Pipelines:

Affiliates – refined product pipelines

127,151

116,727

10,424

Affiliates – intermediate pipelines

148,753

139,502

9,251

Affiliates – crude pipelines

297,810

199,627

98,183

573,714

455,856

117,858

Third parties – refined product pipelines

70,675

71,271

(596

)

644,389

527,127

117,262

Terminals and loading racks:

Affiliates

293,074

255,556

37,518

Third parties

77,869

70,364

7,505

370,943

325,920

45,023

Total for pipelines and terminal assets (bpd)

1,015,332

853,047

162,285

Nine Months EndedSeptember 30,

Change from

2015

2014

2014

(In thousands, except per unit data)

Revenues

Pipelines:

Affiliates—refined product pipelines

$

60,731

$

59,520

$

1,211

Affiliates—intermediate pipelines

21,522

21,632

(110

)

Affiliates—crude pipelines

49,483

40,207

9,276

131,736

121,359

10,377

Third parties—refined product pipelines

36,031

30,037

5,994

167,767

151,396

16,371

Terminals, tanks and loading racks:

Affiliates

82,532

82,403

129

Third parties

11,325

10,333

992

93,857

92,736

1,121

Total revenues

261,624

244,132

17,492

Operating costs and expenses

Operations

77,350

72,835

4,515

Depreciation and amortization

46,083

46,953

(870

)

General and administrative

9,659

7,933

1,726

133,092

127,721

5,371

Operating income

128,532

116,411

12,121

Equity in earnings of equity method investments

2,634

2,150

484

Interest expense, including amortization

(27,310

)

(27,368

)

58

Interest income

384

3

381

Loss on early extinguishment of debt

—

(7,677

)

7,677

Other

406

45

361

(23,886

)

(32,847

)

8,961

Income before income taxes

104,646

83,564

21,082

State income tax expense

(106

)

(145

)

39

Net income

104,540

83,419

21,121

Allocation of net income attributable to noncontrolling interests

(7,851

)

(6,562

)

(1,289

)

Net income attributable to Holly Energy Partners

96,689

76,857

19,832

General partner interest in net income, including incentive distributions (1)

(30,835

)

(25,334

)

(5,501

)

Limited partners’ interest in net income

$

65,854

$

51,523

$

14,331

Limited partners’ earnings per unit—basic and diluted(1)

$

1.11

$

0.87

$

0.24

Weighted average limited partners’ units outstanding

58,657

58,657

—

EBITDA(2)

$

169,804

$

158,997

$

10,807

Distributable cash flow(3)

$

143,495

$

130,883

$

12,612

Volumes (bpd)

Pipelines:

Affiliates—refined product pipelines

121,564

119,718

1,846

Affiliates—intermediate pipelines

143,361

140,505

2,856

Affiliates—crude pipelines

292,158

185,131

107,027

557,083

445,354

111,729

Third parties—refined product pipelines

71,915

60,492

11,423

628,998

505,846

123,152

Terminals and loading racks:

Affiliates

282,299

262,458

19,841

Third parties

77,011

68,185

8,826

359,310

330,643

28,667

Total for pipelines and terminal assets (bpd)

988,308

836,489

151,819

September 30,

December 31,

2015

2014

(In thousands)

Balance Sheet Data

Cash and cash equivalents

$

10,856

$

2,830

Working capital

$

13,857

$

3,140

Total assets

$

1,466,029

$

1,401,555

Long-term debt

$

951,067

$

867,579

Partners’ equity(4)

$

293,797

$

320,362

(1)

Net income attributable to Holly Energy Partners is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. Net income allocated to the general partner includes incentive distributions declared subsequent to quarter end. General partner incentive distributions were $10.3 million and $8.5 million for the three months ended September 30, 2015 and 2014, respectively, and $29.5 million and $24.3 million for the nine months ended September 30, 2015 and 2014, respectively.

(2)

Earnings before interest, taxes, depreciation and amortization (“EBITDA”) is calculated as net income attributable to Holly Energy Partners plus (i) interest expense and loss on early extinguishment of debt, net of interest income, (ii) state income tax and (iii) depreciation and amortization. EBITDA is not a calculation based upon GAAP. However, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements. EBITDA should not be considered as an alternative to net income attributable to Holly Energy Partners or operating income, as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA also is used by our management for internal analysis and as a basis for compliance with financial covenants.

Set forth below is our calculation of EBITDA.

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

2015

2014

2015

2014

(In thousands)

Net income attributable to Holly Energy Partners

$

34,485

$

29,680

$

96,689

$

76,857

Add (subtract):

Interest expense

8,992

8,148

25,885

25,984

Interest Income

(381

)

—

(384

)

(3

)

Amortization of discount and deferred debt charges

494

437

1,425

1,384

Loss on early extinguishment of debt

—

—

—

7,677

State income tax expense

69

42

106

145

Depreciation and amortization

16,326

15,483

46,083

46,953

EBITDA

$

59,985

$

53,790

$

169,804

$

158,997

(3)

Distributable cash flow is not a calculation based upon GAAP. However, the amounts included in the calculation are derived from amounts presented in our consolidated financial statements, with the general exception of maintenance capital expenditures. Distributable cash flow should not be considered in isolation or as an alternative to net income attributable to Holly Energy Partners or operating income, as an indication of our operating performance, or as an alternative to operating cash flow as a measure of liquidity. Distributable cash flow is not necessarily comparable to similarly titled measures of other companies. Distributable cash flow is presented here because it is a widely accepted financial indicator used by investors to compare partnership performance. It is also used by management for internal analysis and our performance units. We believe that this measure provides investors an enhanced perspective of the operating performance of our assets and the cash our business is generating.

Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives. Maintenance capital expenditures include expenditures required to maintain equipment reliability, tankage and pipeline integrity, and safety and to address environmental regulations.

(4)

As a master limited partnership, we distribute our available cash, which historically has exceeded our net income attributable to Holly Energy Partners because depreciation and amortization expense represents a non-cash charge against income. The result is a decline in partners’ equity since our regular quarterly distributions have exceeded our quarterly net income attributable to Holly Energy Partners. Additionally, if the assets contributed and acquired from HollyFrontier while we were a consolidated variable interest entity of HollyFrontier had been acquired from third parties, our acquisition cost in excess of HollyFrontier’s basis in the transferred assets of $305.3 million would have been recorded as increases to our properties and equipment and intangible assets at the time of acquisition instead of decreases to partners’ equity.